Improved production of heavy API group ii base oil

Abstract

To provide an improved process and a refining process unit for producing API Group II base oils from a feed containing aromatic extracts.SOLUTION: A method for producing heavy base oil comprises: (a) performing aromatic extraction of a first hydrocarbon feed and a waxy raffinate to generate an aromatic extract; (b) mixing the aromatic extract with a second hydrocarbon feed to produce a mixed feed having a sulfur content exceeding 2000 wt.ppm; and (c) supplying the mixed feed to a hydrotreating unit to produce a heavy API Group II base oil having a kinematic viscosity of 22.6-100 mm2 / s at 70°C. In addition, an integrated refining process unit for producing the heavy base oil is provided.SELECTED DRAWING: Figure 1

Description

[Technical Field]

[0001] This application relates to a method for producing heavy API Group II base oils and an integrated refinery process unit for producing heavy API Group I base oils and heavy API Group II base oils. [Background technology]

[0002] There is a need for improved processes and refinery process units for producing API Group II base oils from feeds containing aromatic extracts. Summary of the Invention

[0003] This application is a. performing an aromatic extraction of a first hydrocarbon feed to produce an aromatic extract and a waxy raffinate for further solvent dewaxing; b. blending the aromatic extract with a second hydrocarbon feed to produce a blended feed having greater than 2000 ppm sulfur by weight; c. Mixed feed is heated at 70°C for 22.6 to 100 mm. 2 1. A hydroprocessing unit configured to produce a heavy API Group II base oil having a kinematic viscosity of 1000 psi or more. The present invention provides a method for producing a heavy base oil, comprising:

[0004] This application also a. i. a solvent dewaxing unit configured to produce a heavy API Group I base oil; and ii. 22.6 to 100 mm at 70°C 2 a hydrotreating unit configured to produce a heavy API Group II base oil having a kinematic viscosity of 1000 kJ / s; an aromatic extraction unit fluidly connected to the b. a first line from the aromatic extraction unit that feeds aromatic extract from the aromatic extraction unit to a second hydrocarbon feed in a second line or vessel to produce a mixed feed having greater than 2000 ppm sulfur by weight; and c. A connection from a second line or vessel to the hydrotreating unit that supplies the mixed feed to the hydrotreating unit. The present invention provides an integrated refining process unit for producing heavy base oil, comprising:

[0005] The present invention, as described herein, may properly comprise, consist of, or consist essentially of the elements of the claims. [Brief explanation of the drawings]

[0006] [Figure 1] FIG. 1 is a process flow diagram of a conventional process scheme for producing API Group I heavy base oils.

[0007] [Figure 2] FIG. 2 is a process flow diagram of an improved integrated refinery process unit for producing heavy base oils, including heavy API Group II base oils and heavy API Group I base oils.

[0008] [Figure 3] FIG. 3 is a chart of the viscosity index of the stripper bottoms (STB) product produced by the process of the present invention.

[0009] [Figure 4] FIG. 4 is a chart of SUS viscosity at 100° F. (37.78° C.) of stripper bottoms products made by the process of the present invention.

[0010] [Figure 5] FIG. 5 is a chart of the aniline point of the stripper bottoms product produced by the process of the present invention.

[0011] [Figure 6] FIG. 6 is a chart of the aromatic hydrocarbon analysis by 22×22 mass spectrometry of the stripper bottoms product produced by the process of the present invention.

[0012] [Figure 7] FIG. 7 is a chart of naphthenic hydrocarbon analysis by 22×22 mass spectrometry of the stripper bottoms product produced by the process of the present invention.

[0013] [Figure 8] FIG. 8 is a chart of a paraffinic hydrocarbon analysis by 22×22 mass spectrometry of the stripper bottoms product produced by the process of the present invention.

[0014] [Figure 9] FIG. 9 is a chart of the UV absorbance at 226 nm of the stripper bottoms product produced by the process of the present invention.

[0015] [Figure 10] FIG. 10 is a chart of the UV absorbance at 255 nm of the stripper bottoms product produced by the process of the present invention.

[0016] [Figure 11] FIG. 11 is a chart of the UV absorbance at 272 nm of the stripper bottoms product produced by the process of the present invention.

[0017] [Figure 12] FIG. 12 is a chart of the yield of stripper bottoms product boiling above 950°F (510°C) produced by the process of the present invention.

[0018] [Figure 13] FIG. 13 is a chart of the yield of stripper bottoms product boiling in the range of 700-950°F (371-510°C) produced by the process of the present invention.

[0019] [Figure 14]FIG. 14 is a chart of the yield of stripper bottoms product boiling in the range of 550°F (288°C) to 700°F (371°C) produced by the process of the present invention.

[0020] [Figure 15] FIG. 15 is a chart of yields of stripper bottoms products boiling in the range of C5 to 550°F (288°C) produced by the process of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0021] Glossary "API Base Oil Categories are classifications of base oils that meet different criteria as shown in Table 1. [Table 1]

[0022] "Group II+" is an informal, industry-established "category" that is a subset of API Group II base oils with a VI above 110, typically between 112 and 119.

[0023] "Heavy sulfur fuel oil" (HSFO) is a low-value oil with more than 1% sulfur by weight. It has traditionally been used as a bunker fuel. HFSO requires expensive upgrading and desulfurization for use as a marine fuel due to recent regulations requiring lower sulfur levels.

[0024] "Aromatic extraction" is part of the process used to produce solvent neutral base oil. During aromatic extraction, vacuum gas oil, deasphalted oil, or a mixture thereof is extracted with a solvent in a solvent extraction unit. Aromatic extraction produces a waxy raffinate and an aromatic extract after evaporation of the solvent.

[0025] "Vacuum gas oil" (VGO) is a by-product of crude oil vacuum distillation that is sent to a hydrotreating unit or aromatics extraction for upgrading to base oil. VGO contains hydrocarbons with a boiling range distribution between 343°C (649°F) and 538°C (1000°F) at 0.101 MPa.

[0026] "Deasphalted Oil" (DAO) refers to the residue from a solvent deasphalted vacuum distillation unit. Solvent deasphalting in refineries is described in J. Speight: Synthetic Fuels Handbook, ISBN 007149023X, 2008, pp. 64, 85-85 and 121.

[0027] "Raffinate" refers to the portion of the original liquid (e.g., VGO or DAO) that remains after the other components have been dissolved and removed by the solvent.

[0028] "Aromatic extract" is one of the products from aromatic extraction after evaporation of the solvent. In the past, it has been used as an HSFO because it typically contains more than 1% sulfur by weight.

[0029] "Solvent dewaxing" is a dewaxing process by crystallization of paraffins at low temperatures and separation by filtration. Solvent dewaxing produces a dewaxed oil and a slack wax. The dewaxed oil can be further hydrofinished to produce base oils.

[0030] "Hydroprocessing" refers to a process in which a carbonaceous feedstock is contacted with hydrogen and a catalyst at elevated temperatures and pressures for the purpose of removing undesirable impurities and / or converting the feedstock into desired products. Examples of hydroprocessing processes include hydrocracking, hydrotreating, catalytic dewaxing, and hydrofinishing.

[0031] "Hydrocracking" refers to a process in which hydrogenation and dehydrogenation are accompanied by the cracking / fragmentation of hydrocarbons, such as converting heavy hydrocarbons to lighter hydrocarbons or converting aromatics and / or cycloparaffins (naphthenes) to acyclic branched paraffins.

[0032] "Hydrotreating" refers to the process of converting sulfur- and / or nitrogen-containing hydrocarbon feeds into hydrocarbon products having reduced sulfur and / or nitrogen content, typically in conjunction with a hydrocracking function, and producing hydrogen sulfide and / or ammonia (respectively) as by-products.

[0033] "Catalytic dewaxing" or hydroisomerization refers to the process of isomerizing normal paraffins to their more branched counterparts in the presence of hydrogen and over a catalyst.

[0034] "Hydrofinishing" refers to a process intended to improve the oxidative stability, UV stability, and appearance of hydrofinished products by removing trace amounts of aromatics, olefins, color bodies, and solvents. As used in this disclosure, the term "UV stability" refers to the stability of hydrocarbons tested when exposed to UV light and oxygen. Instability is indicated when a visible precipitate forms (usually seen as flocs or haze) or when the product darkens upon exposure to ultraviolet light and air. A general description of hydrofinishing can be found in U.S. Pat. Nos. 3,852,207 and 4,673,487.

[0035] "Hydrocarbon" means a compound or substance that contains hydrogen and carbon atoms, but may include heteroatoms such as oxygen, sulfur, or nitrogen.

[0036] "Slack wax" means a petroleum wax containing 3 to 50% oil content.

[0037] "Kinematic viscosity" refers to the ratio of the kinematic viscosity to the density of an oil at the same temperature and pressure as measured by ASTM D445-15.

[0038] The "Saybolt universal second" (SUS) viscosity is a measure of kinematic viscosity used in classical mechanics. It is measured at a controlled temperature using a Saybolt viscometer at 60 cm 3 The time it takes for oil to flow through a calibrated tube. Although this method is now obsolete in the industry, SUS viscosity can be converted from kinematic viscosity as determined by ASTM D2161-10.

[0039] The "aniline point" of an oil is determined by ASTM D611-12 and is defined as the lowest temperature at which equal amounts of aniline and oil are miscible, i.e., form a single phase when mixed. Because aniline miscibility suggests the presence of similar (i.e., aromatic) compounds in the oil, the aniline point value provides an approximation of the aromatic content of the oil. The lower the aniline point, the higher the aromatic content of the oil, as a lower temperature is required to ensure miscibility.

[0040] "Ultraviolet (UV) absorbance" is a measurement useful for characterizing petroleum products and can be determined by ASTM D2008-12.

[0041] "Heavy base oil" in the context of this disclosure is a base oil having a viscosity of 10 mm at 100°C. 2 This refers to a base oil having a kinematic viscosity greater than / s.

[0042] "Bright Stock" is 180mm at 40℃ 2 / s, e.g., 250 mm at 40°C 2 / s or 400 to 1100 mm at 40°C 2 This refers to a heavy base oil having a kinematic viscosity in the range of 1 / s.

[0043] "Cut point" refers to the temperature on the true boiling point (TBP) curve at which a given degree of separation is reached.

[0044] "TBP" refers to the boiling point of a hydrocarbonaceous feed or product as determined by Simulated Distillation (SimDist) per ASTM D2887-13.

[0045] "Hydrocarbonaceous" means compounds or substances that contain hydrogen and carbon atoms, and may include heteroatoms such as oxygen, sulfur, or nitrogen.

[0046] "LHSV" means liquid hourly space velocity.

[0047] "SCF / B" refers to the unit of standard cubic feet of gas (e.g., nitrogen, hydrogen, air, etc.) per barrel of hydrocarbonaceous feed.

[0048] "Zeolite beta" has linear 12-membered ring channels and intersecting 12-membered ring channels, with a thickness of approximately 15.3T / 1000Å. 3 Zeolite Beta refers to a zeolite having a three-dimensional crystalline structure with a framework density of 1000 .mu.m. Zeolite Beta has the BEA framework described in Ch. Baerlocher and L.B. McCusker, Database of Zeolite Structures: http: / / www.iza-structure.org / databases / .

[0049] The SiO2 / Al2O3 molar ratio (SAR) is determined by ICP elemental analysis. An infinite SAR means that there is no aluminum in the zeolite, i.e., the silica to alumina molar ratio is infinite. In this case, the zeolite is composed essentially entirely of silica.

[0050] "Zeolite USY" refers to an ultra-stabilized Y zeolite. Y zeolite is a synthetic faujasite (FAU) zeolite with an SAR of 3 or greater. Y zeolite may be ultra-stabilized by one or more of hydrothermal stabilization, dealumination, and isomorphous substitution. Zeolite USY may be any FAU-type zeolite with a higher framework silicon content than the starting (as-synthesized) Na-Y zeolite precursor.

[0051] "Catalyst support" refers to a material, usually a solid with a high surface area, onto which a catalyst is adhered.

[0052] "Periodic Table" refers to the version of the IUPAC Periodic Table of the Elements dated June 22, 2007, where the numbering scheme for the Periodic Table Groups is as set forth in Chemical And Engineering News, 63(5), 27 (1985).

[0053] "OD acidity" refers to the amount of bridging hydroxyl groups exchanged with deuterated benzene at 80°C by Fourier transform infrared spectroscopy (FTIR). OD acidity is a measure of the density of Bronsted acid sites in the catalyst. The extinction coefficient of the OD signal is 1 The OD was determined by analysis of a standard zeolite beta sample calibrated by H magic angle spinning nuclear magnetic resonance (MAS NMR) spectroscopy. The correlation between OD and OH extinction coefficient was obtained as follows:

[0054]

number

[0055] "Domain size" is the calculated area (units: nm) of structural units observed and measured in zeolite beta catalyst. Domains are described by Paul A. Wright et al., "Direct Observation of Growth Defects in Zeolite Beta," JACS Communications, published December 22, 2004. The method used to measure domain size in zeolite beta is described further herein.

[0056] The "Acid Site Distribution Index (ASDI)" is a measure of the concentration of overactive sites in a zeolite. In some embodiments, the lower the ASDI, the more likely the zeolite has greater selectivity for producing heavier middle distillate products.

[0057] "API gravity" means the specific gravity of a petroleum feedstock or product relative to water as determined by ASTM D4052-11.

[0058] "ISO-VG" refers to the viscosity classification recommended for industrial use as defined in ISO 3448:1992.

[0059] "Viscosity Index" (VI) describes the temperature dependence of a lubricant as determined by ASTM D2270-10 (E2011).

[0060] "Multi-ring index" (PCI) refers to a calculation of the amount of polycyclic aromatic compounds present in a hydrocarbon feed. The test method for determining PCI is ASTM D6379-11.

[0061] "Vessel" refers to any container or tube that holds or transports a liquid. Examples of vessels vary and include drums, tanks, pipes, and mixers. Additionally, a vessel may be a process pressure vessel such as a column, reactor, or heat exchanger.

[0062] Detailed Description Aromatic extraction processes use one or more solvents to selectively extract benzene, toluene, and xylenes from the reformate, producing an aromatic extract and a waxy raffinate. In the United States, most commercial aromatic extraction units use one or more of the following processes:

[0063] UDEX developed by Dow Chemical and licensed by Honeywell UOP Tetra (using tetraethylene glycol) and CAROM (developed by Union Carbide and licensed by Linde), and Sulfolane™, developed by Royal Dutch Shell and licensed by Honeywell UOP. A general description of these different aromatic extraction processes can be found at http: / / www.cieng.com / a-111-319-ISBL-Aromatics-Extraction.aspx. In one embodiment, the solvent used for aromatic extraction is furfural, N-methylpyrrolidone (NMP), or a mixture thereof.

[0064] In one embodiment, the waxy raffinate is solvent dewaxed and hydrofinished to produce a heavy API Group I base oil.

[0065] In one embodiment, the aromatic extract comprises greater than 20% by volume aromatic compounds, such as 30-80% by volume aromatic compounds, or 40-65% by volume aromatic compounds. In one embodiment, the aromatic extract has one or more properties within the ranges set forth in Table 2.

[0066] [Table 2]

[0067] The aromatic extract is mixed with a second hydrocarbon feed to form a mixed feed, and the mixed feed is fed to a hydrotreating unit to be heated at 70°C for 22.6 to 100 mm 2 / s to produce a heavy API Group II base oil with a kinematic viscosity of

[0068] The mixed feed has greater than 2000 ppm sulfur by weight, but is hydrotreated in a hydrotreating unit sufficiently configured to produce a superior quality heavy API Group II base oil. In one embodiment, the mixed feed can have greater than 2000 ppm sulfur by weight to 40,000 ppm sulfur by weight.

[0069] In one embodiment, the second hydrocarbon feed can have an initial boiling point of 250°C to less than 340°C. In one embodiment, to optimize the yield of heavy API Group II base oil produced, the second hydrocarbon feed has an initial boiling point of 300°C to less than 340°C. In one embodiment, the aromatic extract and the second hydrocarbon feed are combined into a mixed feed having an initial boiling point of less than 340°C (644°F). In one embodiment, the mixed feed has an initial boiling point greater than 300°C (572°F). For example, in one embodiment, the mixed feed can have an initial boiling point of 300°C (572°F) to 339°C (642°F).

[0070] In one embodiment, the aromatic extract and the second hydrocarbon feed are combined into a combined feed comprising greater than 3% by weight of the aromatic extract, for example, 5-20% by weight of the aromatic extract.

[0071] In one embodiment, the hydroprocessing unit performs hydrotreating, catalytic dewaxing, and hydrofinishing. In one embodiment, the hydroprocessing unit performs hydrotreating, catalytic dewaxing using a catalytic dewaxing catalyst, and hydrofinishing using a hydrofinishing catalyst.

[0072] In one embodiment, the conditions of the hydroprocessing unit include:

[0073] [Table 3]

[0074] In one embodiment, the operating temperature in the hydroprocessing unit is less than 750°F (399°C), for example, between 650°F (343°C) and 749°F (398°C).

[0075] In one embodiment, conditions within the hydrotreating unit are below 750°F (399°C) to provide 15-35 wt% conversion.

[0076] The refinery equipment used in the processes described herein can consist of conventional process equipment typically used in commercial refinery operations, including aromatic extraction, solvent dewaxing, hydrotreating, hydrocracking, catalytic dewaxing, and hydrofinishing units for the recovery of products and unconverted feedstock, including caustic scrubbers, flash drums, suction traps, acid washes, fractionators, strippers, separators, distillation columns, and the like.

[0077] In one embodiment, hydroprocessing (e.g., hydrotreating, hydrocracking, catalytic dewaxing, or hydrofinishing steps) can be accomplished using one or more fixed bed reactors or reaction zones within a single reactor, each of which can contain one or more catalyst beds of the same or different hydroprocessing catalysts. In one embodiment, a fixed bed is used, although other types of hydroprocessing catalyst beds can also be used. Other types of hydroprocessing catalyst beds suitable for use herein include fluidized beds, ebullated beds, slurry beds, and moving beds.

[0078] In one embodiment, because various hydroprocessing reactions can generally be exothermic, interstage cooling or heating between reactors or reaction zones, or between catalyst beds within the same reactor or reaction zone, can be used in hydroprocessing. A portion of the heat generated during hydroprocessing can be recovered. If this heat recovery option is not available, conventional cooling can be achieved via cooling utilities such as cooling water or air, or through the use of a hydrogen quench stream. In this way, optimal reaction temperatures can be more easily maintained.

[0079] In one embodiment, hydrotreating is carried out in conjunction with hydrocracking using a hydrocracking catalyst in a hydroprocessing unit.

[0080] In one embodiment, the method includes separating stripper bottoms from an effluent of a combined hydrotreating and hydrocracking unit disposed within a hydroprocessing unit, the combined hydrotreating and hydrocracking unit being operated under hydroprocessing conditions with one or more hydrocracking catalysts and having a kinematic viscosity at 70° C. of 22.6 mmHg or less. 2 / s. In one subembodiment, the stripper bottoms separated from the effluent of a combined hydrotreating and hydrocracking unit disposed within the hydrotreating unit comprise 1 to 15 lv% aromatic hydrocarbons, 70 to 90 lv% naphthenic carbons, and 1 to 25 lv% paraffinic hydrocarbons.

[0081] Hydrocracking catalyst In one embodiment, the hydrocracking catalyst comprises at least one hydrocracking catalyst support, one or more metals, optionally one or more molecular sieves, and optionally one or more promoters.

[0082] In one subembodiment, the hydrocracking catalyst support is selected from the group consisting of alumina, silica, zirconia, titanium oxide, magnesium oxide, thorium oxide, beryllium oxide, alumina-silica, alumina-titanium oxide, alumina-magnesium oxide, silica-magnesium oxide, silica-zirconia, silica-thorium oxide, silica-beryllium oxide, silica-titanium oxide, titanium oxide-zirconia, silica-alumina-zirconia, silica-alumina-thorium oxide, silica-alumina-titanium oxide, or silica-alumina-magnesium oxide. In one subembodiment, the hydrocracking catalyst support is alumina, silica-alumina, and combinations thereof.

[0083] In another subembodiment, the hydrocracking catalyst support is an amorphous silica-alumina material having an average mesopore diameter of 70 Å to 130 Å.

[0084] In another subembodiment, the hydrocracking catalyst support is an amorphous silica-alumina material containing SiO in an amount of 10 to 70 wt. % of the bulk dry weight of the hydrocracking catalyst support as determined by ICP elemental analysis, and 450 to 550 m 2 / g BET surface area and a total pore volume of 0.75-1.05 mL / g.

[0085] In another subembodiment, the hydrocracking catalyst support is an amorphous silica-alumina material containing SiO in an amount of 10 to 70 wt. % of the bulk dry weight of the hydrocracking catalyst support as determined by ICP elemental analysis, and 450 to 550 m 2 / g BET surface area, 0.75-1.05 mL / g total pore volume, and an average mesopore diameter of 70-130 Å.

[0086] In one subembodiment, the amount of hydrocracking catalyst support in the hydrocracking catalyst is from 5 wt % to 80 wt % based on the bulk dry weight of the hydrocracking catalyst.

[0087] In one subembodiment, the hydrocracking catalyst is BEA-, ISV-, BEC-, IWR-, MTW-, * STO-, OFF-, MAZ-, MOR-, MOZ-, AFI-, * It may optionally contain one or more molecular sieves selected from the group consisting of NRE, SSY-, FAU-, EMT-, ITQ-21-, ERT-, ITQ-33-, and ITQ-37-type molecular sieves, and mixtures thereof.

[0088] In one subembodiment, the one or more molecular sieves are selected from the group consisting of molecular sieves having a FAU framework topology, molecular sieves having a BEA framework topology, and mixtures thereof.

[0089] In one subembodiment, the amount of molecular sieve material in the hydrocracking catalyst is from 0 wt.% to 60 wt.% based on the bulk dry weight of the hydrocracking catalyst. In another subembodiment, the amount of molecular sieve material in the hydrocracking catalyst is from 0.5 wt.% to 40 wt.%.

[0090] In one subembodiment, the hydrocracking catalyst may optionally contain a non-zeolitic molecular sieve. Examples of usable non-zeolitic molecular sieves include silicoaluminophosphates (SAPO), ferroaluminophosphates, titanaluminophosphates, and the various ELAPO molecular sieves described in U.S. Pat. No. 4,913,799 and the references cited therein. Details regarding the preparation of various non-zeolitic molecular sieves can be found in U.S. Pat. No. 5,114,563 (SAPO); U.S. Pat. No. 4,913,799, and the various references cited therein. Mesoporous molecular sieves, such as the M41S family of materials (J. Am. Chem. Soc., 114:10834 10843 (1992)), MCM-41 (U.S. Pat. Nos. 5,246,689, 5,198,203, 5,334,368), and MCM-48 (Kresge et al., Nature 359:710 (1992)) can also be used.

[0091] In one subembodiment, the molecular sieve comprises a Y zeolite having a unit cell size of 24.15 Å to 24.45 Å. In another subembodiment, the molecular sieve comprises a Y zeolite having a unit cell size of 24.15 Å to 24.35 Å. In another subembodiment, the molecular sieve is a low acidity, highly dealuminated, ultrastable Y zeolite having an alpha value of less than 5 and a Bronsted acidity of 1 to 40 micromoles / g. In one subembodiment, the molecular sieve is a Y zeolite having the properties set forth in Table 4 below.

[0092] [Table 4]

[0093] In another subembodiment, the molecular sieve comprises a Y zeolite having the properties set forth in Table 5 below.

[0094] [Table 5]

[0095] In another subembodiment, the hydrocracking catalyst contains 0.1 wt. % to 40 wt. % (based on the bulk dry weight of the catalyst) of a Y zeolite having the properties set forth in Table 4 above, and 1 wt. % to 60 wt. % (based on the bulk dry weight of the catalyst) of a low acidity, highly dealuminated, ultrastable Y zeolite having an alpha value of less than about 5 and a Bronsted acidity of 1 to 40 micromoles / g.

[0096] In another subembodiment, the hydrocracking catalyst comprises zeolite USY having an ASDI of 0.05 to 0.12.

[0097] In another subembodiment, the hydrocracking catalyst has an OD acidity of 20 to 400 μmol / g and an average domain size of 800 to 1500 nm 2 The average domain size is determined by a combination of transmission electron (TEM) and digital image analysis as follows:

[0098] I. Zeolite Beta Sample Preparation: Zeolite beta samples are prepared by embedding a small amount of zeolite beta in epoxy and microtoming. A description of the appropriate procedure can be found in many standard microscopy textbooks.

[0099] Step 1. Embed a small representative portion of zeolite beta powder in epoxy. Allow the epoxy to cure.

[0100] Step 2. The epoxy containing a representative portion of zeolite beta powder is microtomed to a thickness of 80-90 nm. Microtome sections are collected on 400 mesh, 3 mm copper grids available from microscope suppliers.

[0101] Step 3. To prevent the zeolite beta sample from charging under the electron beam in the TEM, a sufficient layer of conductive carbon is vacuum evaporated onto the microtome section.

[0102] II. TEM Imaging: Step 1. Inspect the zeolite beta sample prepared as above at low magnification, e.g., 250,000-1,000,000x, to select crystals in which the zeolite beta channel can be seen.

[0103] Step 2. The selected zeolite beta crystal was tilted onto its zone axis and focused near the Shazer defocus, and images were recorded at >2,000,000x magnification.

[0104] III. Average domain size (nm 2 ) Image analysis to obtain: Step 1. Analyze the previously recorded TEM digital images using a commercially available image analysis software package.

[0105] Step 2. Isolate individual domains and measure domain size in nm 2 The measurement is made in units of 100. Domains whose projections are not clearly visible below the channel view are not included in the measurement.

[0106] Step 3. A statistically relevant number of domains are measured, and the raw data is stored in a computer spreadsheet program.

[0107] Step 4. Descriptive statistics and frequencies are determined. Arithmetic mean (d av ) or the average domain size and standard deviation (s) are calculated using the following formula:

[0108]

number

[0109] In one subembodiment, the average domain size of the zeolite beta is 900 to 1250 nm. 2 , for example, 1000 to 1150 nm 2 is.

[0110] In one embodiment, the hydrocracking catalyst comprises one or more metals. In one embodiment, the one or more metals are selected from the group consisting of elements from Groups 6 and 8-10 of the Periodic Table, and mixtures thereof. In one subembodiment, each metal is selected from the group consisting of nickel (Ni), cobalt (Co), iron (Fe), chromium (Cr), molybdenum (Mo), tungsten (W), and mixtures thereof. In another subembodiment, the hydrotreating catalyst contains at least one Group 6 metal and at least one metal selected from Groups 8-10 of the Periodic Table. Exemplary metal combinations include Ni / Mo / W, Ni / Mo, Ni / W, Co / Mo, Co / W, Co / W / Mo, Ni / Co / W / Mo, and Pt / Pd.

[0111] In one subembodiment, the total amount of metal oxide material in the hydrocracking catalyst is from 0.1 wt.% to 90 wt.% based on the bulk dry weight of the hydrocracking catalyst. In one subembodiment, the hydrocracking catalyst contains from 2 wt.% to 10 wt.% nickel oxide and from 8 wt.% to 40 wt.% tungsten oxide based on the bulk dry weight of the hydrocracking catalyst.

[0112] In one subembodiment, a diluent can be used in forming the hydrocracking catalyst. Suitable diluents include inorganic oxides such as aluminum and silicon oxides, titanium oxide, clay, ceria, and zirconia, and mixtures thereof. In one subembodiment, the amount of diluent in the hydrocracking catalyst is 0% to 35% by weight based on the bulk dry weight of the hydrocracking catalyst. In one subembodiment, the amount of diluent in the hydrocracking catalyst is 0.1% to 25% by weight based on the bulk dry weight of the hydrocracking catalyst.

[0113] In one subembodiment, the hydrocracking catalyst can contain one or more promoters selected from the group consisting of phosphorus (P), boron (B), fluorine (F), silicon (Si), aluminum (Al), zinc (Zn), manganese (Mn), and mixtures thereof. In one subembodiment, the amount of promoter in the hydrocracking catalyst is from 0 wt. % to 10 wt. % based on the bulk dry weight of the hydrocracking catalyst. In one subembodiment, the amount of promoter in the hydrocracking catalyst is from 0.1 wt. % to 5 wt. % based on the bulk dry weight of the hydrocracking catalyst.

[0114] In one embodiment, the hydrotreating conditions for the first or second hydrocracking stage are as follows: total liquid hourly space velocity (LHSV) of about 0.25 to 4.0 hr -1 , for example, about 0.40 to 3.0 hours -1 the hydrogen partial pressure is greater than 200 psig, for example, 500 to 3000 psig; the hydrogen recirculation rate is greater than 500 SCF / B, for example, 1000 to 7000 SCF / B; and the temperature is in the range of 600°F (316°C) to 850°F (454°C), for example, 700°F (371°C) to 850°F (454°C).

[0115] Catalytic dewaxing catalyst In one embodiment, the catalyst used to carry out the catalytic dewaxing process comprises at least one dewaxing catalyst support, one or more noble metals, one or more molecular sieves, and optionally one or more promoters.

[0116] In one subembodiment, the dewaxing catalyst support is selected from the group consisting of alumina, silica, zirconia, titanium oxide, magnesium oxide, thorium oxide, beryllium oxide, alumina-silica, alumina-titanium oxide, alumina-magnesium oxide, silica-magnesium oxide, silica-zirconia, silica-thorium oxide, silica-beryllium oxide, silica-titanium oxide, titanium oxide-zirconia, silica-alumina-zirconia, silica-alumina-thorium oxide, silica-alumina-titanium oxide, or silica-alumina-magnesium oxide, preferably alumina, silica-alumina, and combinations thereof.

[0117] In one subembodiment, the dewaxing catalyst support is an amorphous silica-alumina material having an average mesopore diameter between 70 Å and 130 Å.

[0118] In another subembodiment, the dewaxing catalyst support is a 450-550 ml catalyst containing SiO2 in an amount of 10-70 wt. % of the bulk dry weight of the dewaxing catalyst support as measured by ICP elemental analysis. 2 / g BET surface area, and a total pore volume of 0.75 to 1.05 mL / g.

[0119] In another subembodiment, the dewaxing catalyst support contains SiO in an amount of 10 to 70 wt. % of the bulk dry weight of the dewaxing catalyst support as determined by ICP elemental analysis, and SiO in an amount of 450 to 550 m 2 / g BET surface, a total pore volume of 0.75-1.05 mL / g, and an average mesopore diameter of 70 Å-130 Å.

[0120] In one subembodiment, the amount of dewaxing catalyst support in the catalytic dewaxing catalyst is from 5% to 80% by weight based on the bulk dry weight of the catalytic dewaxing catalyst.

[0121] In one embodiment, the catalytic dewaxing catalyst can optionally contain one or more molecular sieves selected from the group consisting of SSZ-32, small crystallite SSZ-32 (SSZ-32x), SSZ-91, ZSM-23, ZSM-48, EU-2, MCM-22, ZSM-5, ZSM-12, ZSM-22, ZSM-35, and MCM-68 type molecular sieves, and mixtures thereof. SSZ-91 is described in U.S. patent application Ser. No. 14 / 837,071, filed August 27, 2015. In one embodiment, the catalytic dewaxing catalyst can optionally contain a non-zeolitic molecular sieve. Examples of non-zeolitic molecular sieves that can be used include silicoaluminophosphate (SAPO), ferroaluminophosphate, titanium aluminophosphate, and the various ELAPO molecular sieves mentioned above.

[0122] In one embodiment, the amount of molecular sieve material in the catalytic dewaxing catalyst can be from 0% to 80% by weight, based on the bulk dry weight of the catalytic dewaxing catalyst. In one subembodiment, the amount of molecular sieve material in the catalytic dewaxing catalyst is from 0.5% to 40% by weight. In one subembodiment, the amount of molecular sieve material in the catalytic dewaxing catalyst is from 35% to 75% by weight. In one subembodiment, the amount of molecular sieve material in the catalytic dewaxing catalyst is from 45% to 75% by weight.

[0123] In one embodiment, the catalytic dewaxing catalyst contains one or more precious metals selected from the group consisting of elements from Group 10 of the Periodic Table and mixtures thereof. In one subembodiment, each precious metal is selected from the group consisting of platinum (Pt), palladium (Pd), and mixtures thereof.

[0124] Hydrofinishing Catalyst In one embodiment, the hydrofinishing catalyst used in carrying out the hydrofinishing process comprises at least one hydrofinishing catalyst support, one or more metals, and optionally one or more promoters.

[0125] In one subembodiment, the hydrofinishing catalyst support can be selected from the group consisting of alumina, silica, zirconia, titanium oxide, magnesium oxide, thorium oxide, beryllium oxide, alumina-silica, alumina-titanium oxide, alumina-magnesium oxide, silica-magnesium oxide, silica-zirconia, silica-thorium oxide, silica-beryllium oxide, silica-titanium oxide, titanium oxide-zirconia, silica-alumina-zirconia, silica-alumina-thorium oxide, silica-alumina-titanium oxide, or silica-alumina-magnesium oxide. In one subembodiment, the hydrofinishing catalyst support is alumina, silica-alumina, and combinations thereof.

[0126] In one subembodiment, the hydrofinishing catalyst support is an amorphous silica-alumina material having an average mesopore diameter between 70 Å and 130 Å.

[0127] In another subembodiment, the hydrofinished catalyst support comprises SiO2 in an amount of 10 to 70 wt. % of the bulk dry weight of the hydrofinished catalyst support as determined by ICP elemental analysis, and SiO2 in an amount of 450 to 550 m 2 It is an amorphous silica-alumina material with a BET surface area of ​​0.75-1.05 mL / g and a total pore volume of 0.75-1.05 mL / g.

[0128] In another subembodiment, the hydrofinished catalyst support contains SiO2 in an amount of 10 to 70 wt. % of the bulk dry weight of the hydrofinished catalyst support as determined by ICP elemental analysis, and SiO2 in an amount of 450 to 550 m 2 / g, a total pore volume of 0.75-1.05 mL / g, and an average mesopore diameter of 70-13 Å.

[0129] In one embodiment, the amount of hydrofinishing catalyst support in the hydrofinishing catalyst is from 5 wt % to 80 wt % based on the bulk dry weight of the hydrofinishing catalyst.

[0130] In one embodiment, the hydrofinishing catalyst may contain one or more metals selected from the group consisting of elements from Groups 6 and 8-10 of the periodic table, and mixtures thereof. In one subembodiment, each metal is selected from the group consisting of nickel (Ni), cobalt (Co), iron (Fe), chromium (Cr), molybdenum (Mo), tungsten (W), and mixtures thereof. In another subembodiment, the hydrofinishing catalyst contains at least one Group 6 metal and at least one metal selected from Groups 8-10 of the periodic table. Examples of metal combinations in the hydrofinishing catalyst include Ni / Mo / W, Ni / Mo, Ni / W, Co / Mo, Co / W, Co / W / Mo, Ni / Co / W / Mo, and Pt / Pd.

[0131] In one subembodiment, the total amount of metal oxide material in the hydrofinishing catalyst is from 0.1 wt.% to 90 wt.% based on the bulk dry weight of the hydrofinishing catalyst. In one subembodiment, the hydrofinishing catalyst contains from 2 wt.% to 10 wt.% nickel oxide and from 8 wt.% to 40 wt.% tungsten oxide based on the bulk dry weight of the hydrofinishing catalyst.

[0132] In one embodiment, a diluent can be used in forming the hydrofinishing catalyst. Suitable diluents include inorganic oxides such as aluminum and silicon oxides, titanium oxide, clay, ceria, and zirconia, and mixtures thereof. In one subembodiment, the amount of diluent in the hydrofinishing catalyst can be from 0% to 35% by weight based on the bulk dry weight of the hydrofinishing catalyst. In one subembodiment, the amount of diluent in the hydrofinishing catalyst is from 0.1% to 25% by weight based on the bulk dry weight of the hydrofinishing catalyst.

[0133] In one subembodiment, the hydrofinishing catalyst may contain one or more promoters selected from the group consisting of phosphorus (P), boron (B), fluorine (F), silicon (Si), aluminum (Al), zinc (Zn), manganese (Mn), and mixtures thereof. In one subembodiment, the amount of promoter in the hydrofinishing catalyst may be 0 wt.% to 10 wt.% based on the bulk dry weight of the hydrofinishing catalyst. In one subembodiment, the amount of promoter in the hydrofinishing catalyst is 0.1 wt.% to 5 wt.% based on the bulk dry weight of the hydrofinishing catalyst.

[0134] In one subembodiment, the hydrofinishing catalyst is a bulk metallic or multi-metallic catalyst, where the amount of metal in the hydrofinishing catalyst is 30 wt. % or greater, based on the bulk dry weight of the hydrofinishing catalyst.

[0135] Base Oil Products Heavy API Group II base oils have a viscosity of 22.6 to 100 mmHg at 70°C. 2 / s kinematic viscosity. In one embodiment, the heavy API Group II base oil has a VI of less than 130. In one embodiment, the heavy API Group II base oil has a VI of 100 to 120. In one subembodiment, the heavy API Group II base oil has a VI of 106 to 116.

[0136] In one embodiment, the API Group II base oil has less than 10 ppm by weight of nitrogen. In one embodiment, the heavy API Group II base oil has less than 3 ppm by weight of nitrogen. For example, in one embodiment, the heavy API Group II base oil can have 0 to 3 ppm by weight of nitrogen. In different subembodiments, the heavy API Group II base oil has less than 1 ppm by weight of nitrogen and a VI of less than 116, or the heavy API Group II base oil has 1 to 2 ppm by weight of nitrogen and a VI of less than 110.

[0137] In one embodiment, the API Group II base oil has an aniline point of less than 285°F (140.6°C). In one embodiment, the heavy API Group II base oil has an aniline point of less than 270°F (132.2°C), for example, 250-270°F (121.1-132.2°C). In a subembodiment, the heavy API Group II base oil has less than 1.5 ppm by weight nitrogen and an aniline point of less than 260°F (126.7°C).

[0138] In one embodiment, heavy API Group II base oils have excellent utility in industrial oils. For industrial oils, a reference temperature of 40°C represents the operating temperature of machinery, and industrial oils can be assigned an ISO-VG classification. Each successive viscosity grade (VG) in the ISO-VG classification has approximately 50% higher viscosity, but the minimum and maximum values ​​for each grade range ±10% from the midpoint. For example, ISO-VG 22 has a viscosity of 22 mm at 40°C. 2 / s ±10%. Viscosity at different temperatures can be calculated using the viscosity at 40°C and the viscosity index (VI), which indicates the temperature dependency of the lubricant. Table 6 shows the range of kinematic viscosity at 40°C for different ISO-VG classifications.

[0139] [Table 6]

[0140] In one embodiment, the process for producing the base oil further comprises distilling the heavy API Group II base oil to produce bright stock. In a subembodiment, the bright stock may have an ISO-VG of ISO-VG320 or ISO-VG460.

[0141] Integrated Refining Process Unit An example of one embodiment of an integrated refinery process unit is shown in Figure 2. The integrated refinery process unit includes a solvent dewaxing unit that produces heavy base oil and produces a heavy API Group I base oil, and a 22.6-100 mm 2The integrated refinery process includes an aromatics extraction unit fluidly coupled to both a hydrotreating unit and a hydrocarbon extraction unit for producing a heavy API Group II base oil having a kinematic viscosity of 1000 ppm / s. In this embodiment, the integrated refinery process unit has a line that supplies an aromatic extract from the aromatics extraction unit to another line that supplies a second hydrocarbon feed from the aromatics extraction unit to create a mixed feed. The mixed feed is supplied to the hydrotreating unit. The mixed feed supplied to the hydrotreating unit has a sulfur content greater than 2,000 ppm by weight.

[0142] In one embodiment, the hydroprocessing units within the integrated refinery process unit include a hydrotreating unit, a catalytic dewaxing unit, and a hydrofinishing unit, with the hydroprocessing conditions and catalysts used in these units being as described previously in this disclosure.

[0143] In one embodiment, the combined hydrotreating and hydrocracking unit is located within the hydrotreating unit. In a subembodiment, the combined hydrotreating and hydrocracking unit is configured to operate under hydrotreating conditions and contains one or more hydrocracking catalysts such that the combined hydrotreating and hydrocracking unit produces a pulverulent gas of 22.6 to 100 mm H at 70° C. 2 / s. In another subembodiment, the hydrotreating and hydrocracking units can be combined to produce stripper bottoms containing 1-15 lv% aromatic hydrocarbons, 70-90 lv% naphthenic carbons, and 1-25 lv% paraffinic hydrocarbons.

[0144] Solvent Dewaxing As previously described, in one embodiment the waxy raffinate is solvent dewaxed and hydrofinished to produce a heavy API Group I base oil.

[0145] Solvent dewaxing to produce base oils has been used for over 70 years and is described, for example, in Chemical Technology of Petroleum, 3rd Edition, William Gruse and Donald Stevens, McGraw-Hill Book Company, Inc., New York, 1960, pp. 566-570. When used, the basic process for solvent dewaxing involves:

[0146] * mixing the waxy hydrocarbon stream with a solvent; The mixture is cooled to precipitate wax crystals. *Wax is separated by filtration, typically using a rotary drum filter; *Recovering solvent from wax and dewaxed oil filtrate.

[0147] In one embodiment, the solvent used in solvent dewaxing can be recycled to the solvent dewaxing process. Suitable solvents for solvent dewaxing can include, for example, ketones (e.g., methyl ethyl ketone or methyl isobutyl ketone) and aromatics (e.g., toluene). Other types of suitable solvents are auto-refrigerative solvents such as C3-C6 ketones (e.g., methyl ethyl ketone, methyl isobutyl ketone, and mixtures thereof), C6-C10 aromatic hydrocarbons (e.g., toluene), mixtures of ketones and aromatics (e.g., methyl ethyl ketone and toluene), and liquid, usually gaseous, C2-C4 hydrocarbons such as propane, propylene, butane, butylene, and mixtures thereof. Mixtures of methyl ethyl ketone and methyl isobutyl ketone can also be used.

[0148] Since its inception, improvements have been made to solvent dewaxing. For example, Exxon's DILCHILL® dewaxing process involves cooling a waxy hydrocarbon oil stock in an elongated agitated vessel, preferably a vertical tower, using a pre-chilled solvent that solubilizes at least a portion of the oil stock while promoting wax precipitation. The waxy oil is introduced into an elongated, staged cooling zone or tower at a temperature above its cloud point. The cooled dewaxing solvent is gradually introduced into the cooling zone along multiple points or stages, while maintaining a high degree of agitation therein to cause substantially instantaneous mixing of the solvent and wax / oil mixture as they progress through the cooling zone, thereby precipitating at least a portion of the wax in the oil. DILCHILL® dewaxing is discussed in more detail in U.S. Pat. Nos. 4,477,333, 3,773,650, and 3,775,288. Texaco has also developed a refinery for this process. For example, U.S. Patent No. 4,898,674 discloses the importance of controlling the ratio of methyl ethyl ketone (MEK) to toluene and being able to adjust this ratio so that optimal concentrations can be used to process various base stocks. Generally, when processing bright stocks, ratios of 0.7:1 to 1:1 can be used, and when processing light stocks, ratios of 1.2:1 to about 2:1 can be used.

[0149] In one embodiment, the waxy raffinate can be cooled to a temperature in the range of −10° C. to −40° C., or to a temperature in the range of 20° C. to −35° C., to precipitate wax crystals. The precipitated waxy crystals can be separated by filtration. Filtration can be performed using a filter, including a filter cloth, which can be made of any suitable material, including woven fibers, such as cotton; porous metal cloth; or cloth made of synthetic materials.

[0150] In one embodiment, solvent dewaxing conditions include an amount of solvent sufficient to provide, when added to the waxy raffinate, a liquid / solid weight ratio of from about 5:1 to about 20:1, and a solvent / waxy raffinate volume ratio of from 1.5:1 to 5:1 at the dewaxing temperature. [Example]

[0151] Example 1: Aromatic Extract A sample of aromatic extract from a refinery used to produce Group I heavy base oil was obtained and analyzed, as shown in Figure 1. The properties of this aromatic extract were as follows:

[0152] [Table 7]

[0153] Example 2: Deasphalted Oil and Blends of Deasphalted Oil with Aromatic Oil Extract A sample of typical deasphalted oil having a VI of 90 was obtained from a refinery and blended with 10% by volume of the aromatic extract described in Example 1. The properties of these two sample feeds are described below.

[0154] [Table 8]

[0155] Example 3: Hydrotreating of deasphalted oil and blends of deasphalted oil with aromatic extracts The two sample feeds described in Example 2 were hydrotreated in a two-reactor microunit. The first hydrotreating reactor contained a high-activity ISOTREATING® catalyst used as a pretreatment for base oil production. The second reactor contained a layered catalyst system with the same ISOTREATING® catalyst on top and a high-performance ISOCRACKING® catalyst on the bottom. ISOTREATING® and ISOCRACKING® are registered trademarks owned by Chevron Intellectual Property LLC. The second reactor was packed with -100 mesh alundum (a hard material composed of fused alumina) to prevent bypass and channeling. All catalysts were supplied by Advanced Refining Technologies, a joint venture between W.R. Grace and Chevron.

[0156] The two-reactor microunit was pre-sulfided, heat treated, and de-edge by pre-feeding with diesel. Hydroprocessing of the two sample feeds described in Example 2 was carried out using the following process conditions:

[0157] 0.50hr -1 LHSV 2350 psig total pressure (2260 psi inlet H2 partial pressure) ·5000 SCF / B Once-through H2 Reactor temperature of 708°F (376°C) to 725°F (385°C) · 19.63 to 32.13 wt% conversion below 700°F (371°C).

[0158] The effluent from the two-reactor microunit was passed through a stripper with a cut point of about 743°F (about 395°C) to separate and recover a stripper bottoms product boiling in a range suitable for base oil production. Process conditions for hydrotreating were adjusted during each run to produce a stripper bottoms product with either a low nitrogen level of 0.1 to 0.4 wppm or a high nitrogen level of 1.25 to 2.7 wppm.

[0159] Some of the average properties measured for the stripper bottoms products recovered from these hydrotreating runs are shown in Table 9 and charted in Figures 3-11. The yields of various hydrocarbon fractions in the effluents from these hydrotreating runs are shown in Table 10 and charted in Figures 12-15.

[0160] [Table 9]

[0161] [Table 10]

[0162] Slightly higher reactor temperatures (by 5–7°F) were required to achieve the same nitrogen levels in the stripper bottoms product when the deasphalted oil was hydrotreated with the aromatic extract compared to when the deasphalted oil was hydrotreated alone. All stripper bottoms products are excellent feeds for further catalytic dewaxing and distillation to desired Group II base oils, including Group II or Group II+ bright stocks. Bright stocks, produced by further catalytic dewaxing and distillation of stripper bottoms products made from blends of deasphalted oil and aromatic extracts, also have desirable kinematic viscosities at 40°C (e.g., ISO-VG 320 or ISO-VG 460), but they have a moderate VI in the range of 106 to 116, which is currently in short supply in the market. Previous processes for producing API Group II+ or API Group III bright stocks have produced base oils with higher VIs, but these were in the ISO-VG range, which was too low for many industrial oil applications.

[0163] Blending aromatic extracts with deasphalted oil has been shown to upgrade low-value aromatic extracts to a blended waxy feed that produces highly desirable heavy base oil products, significantly increasing the overall yield of high-value Group II and Group II+ base oil products from refineries incorporating this capability. Figures 12 and 13 show the improved yields of products boiling in the 700-950°F and 950°F+ ranges obtained by using the mixed feed in the process of the present invention. Surprisingly, hydrotreating the mixed feed resulted in a yield of more than 36 wt% of products boiling in the 700-950°F range, even when the product nitrogen was less than 3 wt. ppm. This was not achievable by hydrotreating the deasphalted oil alone. Furthermore, blending aromatic extracts with deasphalted oil has been shown to lower the aniline point of the stripper bottoms by at least 2°F compared to operation when the deasphalted oil was hydrotreated alone. A low aniline point is desirable in heavy base oil products because it improves the solubility of additives formulated into the heavy Group II base oil to produce a finished lubricant.

[0164] Example 4: Analysis of aromatic content in feed and stripper bottoms UV absorption of the stripper bottoms product from the run described in Example 3 is shown in Figures 9-11. UV absorption is an indicator of aromatic content in the stripper bottoms. UV absorption results are shown in Figures 9-11 for a run operated under process conditions to produce low nitrogen levels and a run operated under milder process conditions to produce high nitrogen levels. Notably, even though the blend of deasphalted oil and aromatic extract had a significantly higher aromatic content compared to the deasphalted oil feed (see Table 8), the stripper bottoms product produced by hydrotreating the mixed feed had only a slightly higher aromatic content compared to the stripper bottoms product produced by hydrotreating deasphalted oil alone. This feature is also shown in the aromatic hydrocarbon analysis for the same run in Figure 6.

[0165] Example 5: Analysis of Hydrocarbon Types in the Feed and Stripper Bottoms Hydrocarbon type analyses of the feeds and their stripper bottoms products from the runs described in Example 3 are shown in Figures 6-8. Hydrocarbon type analyses are based on the methodology described in Gallegos, EJ; The analysis was performed by 22 × 22 mass spectrometry according to the method described in Green, JW; Lindeman, LP; LeTourneau, RL; Teeter, R. "Petroleum Group-Type Analysis by High Resolution Mass Spectrometry," Anal. Chem. 1967, Vol. 39, pp. 1833-1838. Surprisingly, the hydrocarbon types in the stripper bottoms product from the mixed feed runs were very similar to those in the stripper bottoms product from runs using only deasphalted oil. In all runs, the stripper bottoms product ranged in aromatic hydrocarbon content from 2.9 to 13.8 liquid volume percent (lv%), naphthenic hydrocarbon content from 73 to 86.7 lv%, and paraffinic hydrocarbon content from 2.3 to 24.1 lv%. Furthermore, the sulfur content in all stripper bottoms products was 0 lv%. In the mixed feed runs, the stripper bottoms product had paraffinic hydrocarbon amounts ranging from 6.1 to 8.7 lv%.

[0166] The transitional term "comprising," which is synonymous with "including," "containing," or "characterized by," is inclusive or open-ended and does not exclude additional, unrecited elements or method steps. The transitional phrase "consisting of" excludes elements, steps, or ingredients not specified in the claim. The transitional phrase "consisting essentially of" limits the scope of a claim to specified materials or steps and "which do not materially affect the basic and novel characteristics" of the claimed invention.

[0167] For purposes of this specification and the appended claims, unless otherwise indicated, all numbers expressing quantities, percentages or ratios, and other numerical values ​​used in the specification and claims should be understood in all instances to be modified by the term "about." Moreover, all ranges disclosed herein are inclusive of the endpoints and independently combinable. Whenever a numerical range with a lower and upper limit is disclosed, any number within the range is also specifically disclosed. Unless otherwise specified, all percentages are percent by weight.

[0168] Any term, abbreviation, or shorthand not defined will be understood to have its ordinary meaning as used by one of ordinary skill in the art at the time the application is filed. The singular forms "a," "an," and "the" include plural references unless expressly and unambiguously limited to one instance.

[0169] All publications, patents, and patent applications cited in this application are herein incorporated by reference in their entirety to the same extent as if each individual publication, patent application, or patent disclosure was specifically and individually indicated to be incorporated by reference in its entirety.

[0170] This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. Many variations of the exemplary embodiments of the invention described above will readily occur to those skilled in the art. Accordingly, the invention is to be construed as including all structure and methods that fall within the scope of the appended claims. Unless otherwise specified, the recitation of a group of elements, materials, or other components from which individual components or mixtures of components may be selected is intended to include all possible subgeneric combinations of the listed components and mixtures thereof.

[0171] The invention illustratively disclosed herein may suitably be practiced in the absence of any element not specifically disclosed herein.

Claims

1. A method for producing a heavy base oil, comprising: a. conducting aromatic extraction of the first hydrocarbon feed to produce an aromatic extract and a waxy raffinate for further solvent dewaxing; b. blending the aromatic extract with a second hydrocarbon feed to produce a blended feed having greater than 2000 ppm by weight of sulfur; c. The mixed feed is mixed at 70°C for 22.6 to 100 mm ２ The mixture is fed to a hydrotreating unit configured to produce a heavy API Group II base oil having a kinematic viscosity of 1000 kJ / s: The above method, comprising:

2. 10. The method of claim 1, wherein the aromatic extract comprises 30 to 80 volume percent aromatic compounds.

3. 10. The method of claim 1, wherein the hydroprocessing unit performs hydrotreating, catalytic dewaxing, and hydrofinishing.

4. 10. The method of claim 1, wherein the waxy raffinate is solvent dewaxed and hydrofinished to produce a heavy API Group I base oil.

5. 10. The method of claim 1, wherein the mixed feed has an initial boiling point of less than 340°C.

6. 10. The method of claim 1, wherein the mixed feed comprises 5 to 20 wt. % aromatic extract.

7. 10. The method of claim 1, wherein the heavy API Group II base oil has a VI of 100 to 120.

8. 10. The method of claim 1, wherein the heavy API Group II base oil has less than 1.5 ppm by weight of nitrogen and an aniline point less than 260°F (126.7°C).

9. 10. The method of claim 1, further comprising distilling the heavy API Group II base oil to produce bright stock.

10. 10. The method of claim 9, wherein the bright stock has an ISO-VG of ISO-VG320 or ISO-VG460.

11. 10. The method of claim 1, wherein the operating temperature in the hydroprocessing unit is less than 750°F (399°C).

12. 10. The method of claim 1, wherein the waxy raffinate is solvent dewaxed and hydrofinished to produce a heavy API Group I base oil.

13. % aromatic hydrocarbons, 70-90 lv. % naphthenic carbons, and 1-25 lv. % paraffinic hydrocarbons, and having a viscosity of 22.6 mm at 70° C. ２ 10. The method of claim 1, wherein the method produces stripper bottoms having a kinematic viscosity of greater than 1000 kJ / s.

14. 5. An integrated refinery process unit when used to produce heavy API Group II base oils and heavy API Group I base oils according to the method of claim 4.

15. 1. An integrated refining process unit for producing a heavy base oil, comprising: a. i. a solvent dewaxing unit configured to produce a heavy API Group I base oil; ii. 22.6 to 100 mm at 70°C ２ 1. A hydrotreating unit configured to produce a heavy API Group II base oil having a kinematic viscosity of 1000 kJ / s. an aromatic extraction unit fluidly connected to the b. a first line from the aromatic extraction unit that feeds aromatic extract from the aromatic extraction unit to a second hydrocarbon feed in a second line or vessel to produce a mixed feed having greater than 2000 ppm sulfur by weight; and c. A connection from a second line or vessel to the hydroprocessing unit that supplies the mixed feed to the hydroprocessing unit: The above unit, including:

16. 16. The integrated refinery process unit of claim 15, wherein the hydroprocessing unit comprises a hydrotreating unit, a catalytic dewaxing unit, and a hydrofinishing unit.

17. The combined hydrotreating and hydrocracking unit is disposed within the hydrotreating unit, and the combined hydrotreating and hydrocracking unit is configured to operate under hydrotreating conditions, and the combined hydrotreating and hydrocracking unit is configured to operate under hydrotreating conditions, and the combined hydrotreating and hydrocracking unit is configured to operate under hydrotreating conditions, and ２ 16. The integrated refinery process unit of claim 15, containing one or more hydrocracking catalysts to produce a stripper bottoms having a kinematic viscosity of 1000 kJ / s.

18. 20. The integrated refinery process unit of claim 17, wherein the combined hydrotreating and hydrocracking units are configured to produce stripper bottoms comprising 1-15 lv. % aromatic hydrocarbons, 70-90 lv. % naphthenic carbons, and 1-25 lv. % paraffinic hydrocarbons.

19. 16. The integrated refinery process unit of claim 15, further comprising a distillation unit connected to the hydrotreating unit and configured to produce bright stock.

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